Process for removing nitrogen from natural gas

ABSTRACT

A process for separating the components of a gas mixture comprising methane, nitrogen, and at least one hydrocarbon having at least two carbon atoms, or a mixture of these hydrocarbons, including the following steps: a) demonization of the gas mixture with at least one demethenization column; b) extraction of a liquid comprising at least 85 mol % of the hydrocarbons having at least two carbon atoms, partial condensation of a gas mixture in order to obtain a liquid, at least a portion of which is treated in order to be extracted as denitrogenated natural gas product and a second gas; d) introduction of the second gas and/or the gas mixture into a nitrogen removal column, obtained from which are a gas and a liquid, e) treatment of the gas in a nitrogen removal system in order to produce a gas stream comprising 5 mol % at most of nitrogen.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a 371 of International PCT ApplicationPCT/FR2015/052631, filed Oct. 1, 2015, which claims priority to FrenchPatent Application No. 1552780, filed Apr. 1, 2015, the entire contentsof which are incorporated herein by reference.

BACKGROUND

The present invention relates to a process for separating the componentsof a gas mixture containing methane, nitrogen and hydrocarbons heavierthan methane.

The present invention therefore applies to the processes for removingnitrogen from natural gas with or without recovery of helium.

Natural gas is desirable for use as a fuel intended to be used forheating buildings, in order to provide heat for industrial processes forproducing electricity, for use as a raw material for various synthesisprocesses for producing olefins, polymers and the like.

Natural gas is found in many fields that are at a distance from theusers of natural gas. Natural gas typically consists of methane (C1),ethane (C2) and heavier compounds such as hydrocarbons having at leastthree carbon atoms, such as propane, butane, etc. (C3+).

Often, it may be advantageous to separate the C2 and C3+ compounds fromthe natural gas in order to sell them as separate coproducts.

Specifically, their commercial use is in general greater than thenatural gas itself since they can be used directly for chemicalprocesses (manufacturing ethylene from ethane for example), as motorfuels (C3/C4 is a conventional motor fuel referred to as GPL) or formany other applications.

Another component often present in natural gas is nitrogen. The presenceof nitrogen in natural gas may lead to difficulties in complying withthe specifications for natural gas (typically minimum lower calorificvalue to be met).

This is even truer when the hydrocarbons heavier than methane (C2 andC3+) are removed since these have a higher lower calorific value thanmethane, by removing them the lower calorific value is therefore reducedwhich must then potentially be increased by means of nitrogenseparation. Consequently, a considerable effort has been devoted to theproduction of means for removing the nitrogen present in natural gas.

The natural gas deposits being exploited contain increasing quantitiesof nitrogen. This is notably because fields that are rich enough for noenrichment treatment to be needed before the gas is commercialized arebecoming exhausted and increasingly rare.

These sources of natural gas often also contain helium. The latter canbe put to commercial use by performing a pre-concentration before finaltreatment and liquefaction.

Unconventional resources such as shale gases also share the same problemset: in order to make them commercially viable, it may prove necessaryto increase their calorific value by means of a treatment that consistsin removing nitrogen from the gas.

The most widely used method for separating nitrogen and the hydrocarbonsheavier than methane is “cryogenic separation”. A cryogenic nitrogenseparation process, more specifically a process that uses a doublecolumn, is described in patent application U.S. Pat. No. 4,778,498. Theunits for removing nitrogen from natural gas in general treat gaseswhich originate directly from wells at a high pressure. After removal ofthe nitrogen, the treated gas must be returned to the network, often ata pressure close to the pressure at which it entered it.

During the exploitation of natural gas deposits, many steps may beprovided. One relatively conventional step after the drying and theremoval of the impurities is the separation of the liquids associatedwith the natural gas (NGLs).

There may be many advantages of this step but often the advantage is tomake commercial use of various “heavy” hydrocarbon products containingat least two carbon atoms (C2, C3, etc.) which are generally sold forconsiderably more than the natural gas product.

If the natural gas contains nitrogen, there is a risk of again having anatural gas with too low a calorific value due to the resulting lowcontent of C2, C3, etc. It is therefore typical to then have to separatethe nitrogen from this gas in order to render it marketable.

One conventional solution is to treat the two problems independently.

A first unit carries out the separation of the NGLs (subsequentlyreferred to as NGL unit) whilst a second unit separates the nitrogenfrom the natural gas (subsequently referred to as NRU unit).

This solution has the advantage of operational flexibility. For example,if the NRU unit includes a refrigeration cycle, the associated machineshave a limited reliability, and a failure of a cycle compressor willlead to the shutdown of the NRU but without leading to the shutdown ofthe NGL.

Unfortunately, this shutdown will not be able to be of long durationsince it would then be necessary to flare the production (due to itsexcessively low calorific value). Moreover, this scheme is limited interms of efficiency since all the gas is cooled then reheated in the NGLunit then cooled and reheated in the NRU.

Another solution would consist in wholly integrating the NGL and NRUunits, the problem then becomes that the assembly as a whole will haveto be shut down immediately in the event of failure of the refrigerationcycle of the NRU unit.

The inventors of the present invention have then developed a solutionthat makes it possible to resolve the problems raised above.

SUMMARY

The subject of the present invention is a process for separating thecomponents of a gas mixture to be treated comprising methane, nitrogenand at least one hydrocarbon having at least two carbon atoms, or amixture of these hydrocarbons, comprising the following steps:

a) removing methane from said gas mixture using at least one methaneremoval column;

b) extracting, from the methane removal column, a liquid comprising atleast 85 mol % of hydrocarbons having at least two carbon atomsinitially present in the mixture to be treated;

c) optionally, partially condensing a gas mixture extracted from themethane removal column in order to obtain a liquid, at least one portionof which is treated in order to be extracted as denitrogenated naturalgas product, and a second gas;

d) introducing said second gas and/or the gas mixture into a nitrogenremoval column obtained from which are a gas and a liquid, at least oneportion of which is treated in order to be extracted as denitrogenatednatural gas product;

e) treating said gas from step d) in a nitrogen removal system in orderto produce a gas stream comprising 5 mol % at most of nitrogen and agaseous nitrogen stream comprising at most 8 mol % of methane;

characterized in that the operating temperature between steps b) and c)does not exceed −50° C. and the gas is reheated to a temperature above−10° C. before being cooled to a temperature below −50° C. in saidnitrogen removal system.

More particularly, one subject of the present invention relates to aprocess for separating the components of a gas mixture to be treatedcomprising methane, nitrogen and at least one hydrocarbon having atleast two carbon atoms, or a mixture of these hydrocarbons, comprisingthe following steps:

a) removing methane from said gas mixture using at least one methaneremoval column;

b) extracting, from the methane removal column, a liquid comprising atleast 85 mol % of hydrocarbons having at least two carbon atomsinitially present in the mixture to be treated;

c) partially condensing a gas mixture extracted from the methane removalcolumn in order to obtain a liquid, at least one portion of which istreated in order to be extracted as denitrogenated natural gas product,and a second gas;

d) introducing said second gas into a nitrogen removal column obtainedfrom which are a gas and a liquid, at least one portion of which istreated in order to be extracted as denitrogenated natural gas product;

e) treating said gas from step d) in a nitrogen removal system in orderto produce a gas stream comprising 5 mol % at most of nitrogen and agaseous nitrogen stream comprising at most 8 mol % of methane;characterized in that the operating temperature between steps b) and c)does not exceed −50° C. and the gas is reheated to a temperature above−10° C. before being cooled to a temperature below −50° C. in saidnitrogen removal system.

Furthermore, according to other embodiments, the process that is thesubject of the present invention comprises at least the followingfeatures:

Process as defined above characterized in that step a) comprises thefollowing steps:

at least partially condensing said gas mixture to be treated in order toobtain a two-phase mixture;

injecting the liquid phase of said two-phase mixture into a methaneremoval column at a first injection stage;

injecting the vapor phase of said two-phase mixture into said methaneremoval column at an injection stage different from said first stage.

Process as defined above characterized in that the gas mixture,extracted from the methane removal column, condensed in step c)comprises at most half of the amount of hydrocarbons having more thantwo carbon atoms present in the feed gas.

Process as defined above characterized in that step e) of treating saidgas from step d) in a nitrogen removal system produces a gas streamcomprising 5 mol % at most of nitrogen and a gaseous nitrogen streamcomprising at most 2 mol % of methane.

Process as defined above characterized in that the gas from step d)comprises between 10 mol % and 90 mol % of nitrogen.

Process as defined above characterized in that the liquid extracted fromthe methane removal column during step b) comprises at least 90 mol % ofthe hydrocarbons having at least two carbon atoms and preferably atleast 95 mol %.

Process as defined above characterized in that said gas mixture to betreated comprises 70 mol % of methane, at least 4 mol % of nitrogen and2 mol % of hydrocarbons having at least two carbon atoms.

Process as defined above characterized in that said gas mixture to betreated comprises at least 0.05 mol % of helium.

Process as defined above characterized in that it comprises anadditional step f) following step e) of producing a stream comprising atleast 20 mol % of helium from said nitrogen removal system.

BRIEF DESCRIPTION OF THE DRAWING

The invention will be described in more detail by referring to thefigure that illustrates a process according to the invention.

FIG. 1 illustrates one embodiment of the present invention.

DESCRIPTION OF PREFERRED EMBODIMENTS

A stream 1 of natural gas previously pretreated (separation of water, ofCO₂, of methanol, of very heavy hydrocarbons, that is to say having morethan six or seven carbon atoms (such as C8+ hydrocarbons for example)comprising at least 30 mol % of methane, 0.1 mol % of hydrocarbonsheavier than methane (that is to say comprising at least two carbonatoms) and 4 mol % of nitrogen is introduced into a system 2 enabling anat least partial condensation of said stream 1.

The pressure of this stream 1 is between 20 bara (bar absolute) and 100bara (typically between 30 and 70 bara) and the temperature is close toambient temperature, for example between 10° C. and 30° C.

The system 2 is for example a heat exchanger. The mixture 3 leaving thissystem 2 is in a two-phase (gas and liquid) state. This mixture 3 isintroduced into a phase separator vessel 4.

The operating pressure is between 20 and 100 bara, typically between 30and 70 bara. The temperature of this vessel is between −100° C. and 0°C., typically between −80° C. and −20° C.

The liquid phase 5 from the separator vessel 4 is expanded through avalve 6 then injected, at a pressure between 10 bara and 40 bara and atemperature for example between −110° C. and −30° C., into a methaneremoval column 7.

A methane removal column is understood to mean a distillation unitintended to produce at least two streams of different compositions fromfeed streams originating from the stream 1 of natural gas to be treatedaccording to the process of the present invention.

The at least two streams are the following: one gaseous, depleted inhydrocarbons having at least two carbon atoms, that is to say comprisingless than half of the “heavy” hydrocarbons contained in the feed gas(ethane, propane, butane, etc.) and the other, in liquid form,containing less than 5 mol % of the methane initially present in thestream 1 of natural gas to be treated.

A methane removal unit is understood to mean any system comprising atleast one distillation column for enriching the overhead gas withmethane and depleting the bottom liquid of methane.

At least one portion of the gas phase (one portion only typically) 8from the separator vessel 4 is expanded by means of a turbine 9.

The stream from the turbine 9 is introduced into the column 7 at ahigher stage 10 than the stage where the liquid 5 leaving the valve 6 isintroduced.

A liquid stream 12 of heavier hydrocarbons than methane is recovered inthe bottom portion 16 of the column 7.

A reboiler 11 is placed at a level that makes it possible to reboil thebottom liquid from the column 7 in order to reheat a portion of theliquid of said column for the purpose of adjusting the maximum limit ofmethane contained in the stream 12 of heavy hydrocarbons.

At least 50 mol % (typically, at least 85 mol %) of the heavyhydrocarbons present in the gas mixture 1 to be treated are recovered inthis stream 12. Preferably at least 90% are recovered.

Preferably, the liquid stream 12 of hydrocarbons does not contain morethan 1 mol % of methane.

A heat exchanger 13 may be installed in order to reheat the bottomportion of the column 7 (bottom portion=below the introduction of theliquid originating from the vessel 4). This exchanger is fed by thegaseous feed stream 1. This reheating improves the equilibrium betweensearch for maximum efficiency and purity of the stream leaving themethane removal column 7.

At the top 14 of the column 7 (top=highest outlet of the column), amethane-enriched gas stream 15, typically containing less than 0.5 mol %of hydrocarbons having more than two carbon atoms (containing at mosthalf of the amount of heavy hydrocarbons—having more than 2 carbonatoms—present in the feed gas) is extracted. The temperature of the gasstream 15 is below −80° C.

Consequently, the cold may be recovered by condensing a methane-enrichedgas under pressure. This condensation is carried out owing to a heatexchanger 17 fed both with a portion of the gas stream 8 from theseparator vessel 4 and with the methane-enriched gas stream 15 from thetop 14 of the methane removal column 7.

This is only one example of implementation of the process that is thesubject of the invention. But according to a particular embodiment ofthe invention, a third stream to be condensed could be introduced intothis exchanger.

According to yet another embodiment of the invention, only one of thetwo streams described would be to be condensed.

A methane-enriched gas is understood to mean a gas mixture containingmethane, nitrogen and typically less than 0.5% of hydrocarbons havingmore than two carbon atoms (containing at most half of the amount ofheavy hydrocarbons—having more than 2 carbon atoms—present in the feedgas).

The stream(s) 18 (18 a and 18 b) which has been cooled in the exchanger17 is expanded by means for example of at least one valve 19 (19 a, 19b), then is introduced into an upper portion (upper portion=above thefeed 10 leaving the turbine 9) of the column 7.

The stream 20 which has been reheated in the exchanger 17 contains atmost half of the amount of heavy hydrocarbons—having more than 2 carbonatoms —present in the feed gas.

The gas stream 20 reheated in the exchanger 17, to a temperature between−40° C. and −70° C., preferably of the order of −60° C., is thenpartially condensed by means, for example, of a heat exchanger 21.

At the outlet of this exchanger 21, a two-phase (gas-liquid) stream 22emerges (comprising from 20 to 80 mol % of gas).

Alternatively, it is possible to dispense with the preceding step, thatis to say with the passage of the stream 15, extracted from the top ofthe methane removal column 7, into the heat exchanger 17.

It is therefore possible to maintain the temperature of the stream 15below −80° C. (or even below −100° C.) and to introduce said stream 15directly into the heat exchanger 21 in order to obtain the stream 22.

The stream 22 is then sent to a nitrogen removal system A according tothe invention described below.

In the nitrogen removal system A, the two-phase stream 22 is, after apossible expansion in a valve or a turbine 23, introduced into a phaseseparator vessel 25.

The liquid phase 29 resulting from the phase separator vessel 25 is,after a possible expansion in a valve (not represented in the figure),reheated through heat exchangers 27 then 21 and finally 2 in order torejoin the outlet stream 30 of methane-rich gas produced at the outletof the process.

The outlet stream 30 contains less than 5 mol % of nitrogen.

The gas phase 26 resulting from the separator vessel 25 is partiallycondensed in a heat exchanger 27 then expanded on leaving said exchanger27 by means of a turbine or a valve before being introduced into adistillation column 31.

The distillation column 31 is a nitrogen “stripping” column, the purposeof which is to separate the nitrogen from the methane-enriched outletliquid, also referred to as nitrogen removal column.

The methane-enriched liquid comprises less than 5 mol % of nitrogen. Itis a question here of a distillation column connected to a reboiler 32but not having an associated condenser system.

At the bottom of column 31, at a temperature below −100° C., preferablybelow −110° C., a very methane-rich stream 33 in liquid form isextracted. This stream 33 contains less than 5 mol % of nitrogen,preferentially less than 4%. The liquid stream 33 is then mixed with theliquid phase 29 resulting from the phase separator vessel 25 and followsthe same path to the outlet stream 30.

A portion 32 of the mixed stream containing in part the liquid phase 29and the liquid 33 and reheated through the heat exchanger 27 is recycledto the bottom part 34 of the nitrogen removal column 31.

At the top 35 of column 31, a nitrogen-rich gas stream 36, at atemperature below −110° C., is produced. Said nitrogen-rich stream 36comprises at least 20 mol % of nitrogen.

The nitrogen-rich stream 36 is reheated through successive exchangers27, 21 then 2. These may be one and the same exchanger according to oneparticular embodiment of the invention. And according to anotherparticular embodiment of the invention, more than three exchangers maybe used.

This results in a stream 37, at a temperature close to ambienttemperature (above −10° C. typically and below 50° C.), sent to anadditional nitrogen removal system B.

The objective of the nitrogen removal system B is to produce a gasstream even richer in nitrogen than the stream 37.

This system B may for example include at least one separator vessel anda nitrogen removal column. If the specification of the nitrogen at theoutlet of the system B is strict (<100 ppm typically), it may provenecessary to add a cycle compressor, for example a nitrogen compressor,to the system B in order to provide the reflux needed to obtain thenitrogen purity at the top of the nitrogen removal column of the systemB.

The process that is the subject of the present invention makes itpossible to:

not be obliged to flare the gas in a failure mode of the refrigerationcycle of the nitrogen removal system (failure of the cycle compressor);

improve the efficiency of the process.

Specifically, if a failure takes place in the nitrogen removal system B,it will be possible all the same to continue the implementation of theprocess and produce a large portion, typically at least 80%, of thedesired products (denitrogenated methane) owing to the nitrogen removalsystem A.

This is because the solution proposed is to partially integrate thenitrogen removal system with the system for extracting the productsresulting from the “NGL part”. This partial integration consists inintegrating at least a first separator vessel after the methane removalcolumn of the “NGL process”. Recovered from this first separator vessel,in liquid form, will be at least one portion of the natural gas product.This product will be at least partially denitrogenated, making itpossible in certain cases to attain the specification in terms ofcalorific value of the product. In addition to this first vessel, afirst nitrogen removal column may be integrated into the “NGL part”,this makes it possible to increase the proportion of product at thespecification that is directly produced using the nitrogen removalsystem.

The expression “NGL part” is understood to mean all the steps of theprocess according to the invention prior to step c).

A last very cold part then remains (where the temperature levels reachedare below −140° C.), preferably below −160° C., in which a refrigerationcycle may be used if necessary.

A failure of the refrigeration cycle would then lead to the shutdown ofthe nitrogen removal but will be able to maintain part of the productionof denitrogenated natural gas and also the production of the productsderived from the “NGL part”.

In addition, the use of the process according to the invention makes itpossible, in addition to improving the reliability of the plant, tooptimize the total investment cost by optimizing the number of elementsconstituting the various units for implementing said process relative tothe incoming flow rate in each unit.

Specifically, it will not be necessary to add as many nitrogen removalsystems B as nitrogen removal systems A.

It will be understood that many additional changes in the details,materials, steps and arrangement of parts, which have been hereindescribed in order to explain the nature of the invention, may be madeby those skilled in the art within the principle and scope of theinvention as expressed in the appended claims. Thus, the presentinvention is not intended to be limited to the specific embodiments inthe examples given above.

1.-9. (canceled)
 10. A process for separating the components of a gas mixture to be treated comprising methane, nitrogen and at least one hydrocarbon having at least two carbon atoms, or a mixture of these hydrocarbons, comprising the following steps: a) removing methane from said gas mixture using at least one methane removal column; b) extracting from the methane removal column a liquid comprising at least 85 mol % of hydrocarbons having at least two carbon atoms initially present in the mixture to be treated; c) partially condensing a gas mixture extracted from the methane removal column in order to obtain a liquid, at least one portion of which is treated in order to be extracted as denitrogenated natural gas product, and a second gas; d) introducing said second gas and/or the gas mixture into a nitrogen removal column obtained from which are a gas and a liquid, at least one portion of which is treated in order to be extracted as denitrogenated natural gas product; e) treating said gas from step d) in a nitrogen removal system in order to produce a gas stream comprising 5 mol % at most of nitrogen and a gaseous nitrogen stream comprising at most 8 mol % of methane; wherein the operating temperature between steps b) and c) does not exceed −50° C. and the gas is reheated to a temperature above −10° C. before being cooled to a temperature below −50° C. in said nitrogen removal system.
 11. The process as claimed in claim 10, wherein step a) comprises the following steps: at least partially condensing said gas mixture to be treated in order to obtain a two-phase mixture; injecting the liquid phase of said two-phase mixture into a methane removal column at a first injection stage; injecting the vapor phase of said two-phase mixture into said methane removal column at an injection stage different from said first stage.
 12. The process as claimed in claim 10, wherein the gas mixture, extracted from the methane removal column, condensed in step c) comprises at most half of the amount of hydrocarbons having more than two carbon atoms present in the feed gas.
 13. The process as claimed in claim 10, wherein step e) of treating said gas from step d) in a nitrogen removal system produces a gas stream comprising 5 mol % at most of nitrogen and a gaseous nitrogen stream comprising at most 2 mol % of methane.
 14. The process as claimed in claim 10, wherein the gas from step d) comprises between 10 mol % and 90 mol % of nitrogen.
 15. The process as claimed in claim 10, wherein the liquid extracted from the methane removal column during step b) comprises at least 90 mol % of the hydrocarbons having at least two carbon atoms and preferably at least 95 mol %.
 16. The process as claimed in claim 10, wherein said gas mixture to be treated comprises 70 mol % of methane, at least 4 mol % of nitrogen and 2 mol % of hydrocarbons having at least two carbon atoms.
 17. The process as claimed in claim 16, wherein said gas mixture to be treated comprises at least 0.05 mol % of helium.
 18. The process as claimed in claim 17, further comprising an additional step f) following step e) of producing a stream comprising at least 20 mol % of helium from said nitrogen removal system. 